A widely used technique for searching for hydrocarbons, e.g., oil and/or gas, is the seismic exploration of subsurface geophysical structures. Reflection seismology is a method of geophysical exploration to determine the properties of a portion of a subsurface layer in the earth, which information is especially helpful in the oil and gas industry. Marine-based seismic data acquisition and processing techniques are used to generate a profile (image) of a geophysical structure (subsurface) of the strata underlying the seafloor. This profile does not necessarily provide an accurate location for oil and gas reservoirs, but it may suggest, to those trained in the field, the presence or absence of oil and/or gas reservoirs. Thus, providing an improved image of the subsurface in a shorter period of time is an ongoing process.
The seismic exploration process includes generating seismic waves (i.e., sound waves) directed toward the subsurface area, gathering data on reflections of the generated seismic waves at interfaces between layers of the subsurface, and analyzing the data to generate a profile (image) of the geophysical structure, i.e., the layers of the investigated subsurface. This type of seismic exploration can be used both on the subsurface of land areas and for exploring the subsurface of the ocean floor.
Marine reflection seismology is based on the use of a controlled source that sends energy waves into the earth, by first generating the energy waves in or on the ocean. By measuring the time it takes for the reflections to come back to one or more receivers (usually very many, perhaps on the order of several hundreds, or even thousands), it is possible to estimate the depth and/or composition of the features causing such reflections. These features may be associated with subterranean hydrocarbon deposits.
Seismic waves are initiated by a source, and follow one or more paths based on reflection and refraction until a portion of the seismic waves is detected by one or more receivers. Upon detection, data associated with the seismic waves is recorded and then processed for producing an accurate image of the subsurface. The processing can include various phases, e.g., velocity model determination, pre-stack, migration, post-stack, etc., which are known in the art and thus their description is omitted here.
A traditional marine system for recording seismic waves is illustrated in FIG. 1, and this system is described in European Patent No. EP 1 217 390, the entire content of which is incorporated herein by reference. In this document, a plurality of seismic receivers 2 are each removably attached to a pedestal 4 together with a memory device 6. A plurality of such receivers is deployed on the bottom 8 of the ocean. A source vessel 10 tows a seismic source 12 that is configured to emit seismic wave 14. The seismic source may be configured to emit impulsive energy, e.g. air gun array or dynamite, or non-impulsive energy, e.g. marine vibrator. Seismic wave 14 propagates downward, toward the ocean bottom 8. After being reflected from a structure 16, the seismic wave (primary) is recorded (as a trace) by the seismic receiver 2. Those skilled in the art will appreciate that while FIG. 1 describes one example of a marine seismic acquisition system various other and different configurations are known, e.g., wherein the receivers are also towed by the vessel. Some of these other configurations will be described below.
Receivers 2 can be implemented as hydrophones or as so-called multi-component receivers. Multi-component marine acquisition uses receivers that are capable of measuring a pressure wavefield and at least one component of a particle motion that is associated with acoustic signals that are reflected/refracted versions of the signal generated by the source 12. Examples of particle motions which can be sensed by multi-component receivers include one or more components of a particle displacement, one or more components of a particle velocity (for example, inline (X), crossline (Y) and vertical (Z) components) and one or more components of a particle acceleration, i.e., vectorial motion measurements. Particle motion, particle velocity, and particle acceleration recordings may be processed to simulate each other. For example, particle acceleration recordings may be integrated in time to convert to particle velocity data. Such integration may be applied in the time domain or in the frequency domain. As such, the terms particle motion, particle velocity, and particle acceleration are used interchangeable throughout this document.
The vectorial motion measurements convey both direction and polarity information in contrast to pressure measurements which is direction independent. A 3D vector describing the incident pressure wavefield can be resolved from the apparent velocity measurements of different components, e.g., Vz, Vy, and Vx (if available). These are the vertical and horizontal, cross-line and in-line, components of the apparent velocity of particles moving within a pressure wave incident at a multi-component sensor(s). The polarization allows discrimination between upcoming and down-going seismic energy, in addition to cross-line Y and in-line X (if available) directionality, where “in-line” may be defined as the direction of progression of the marine vessel towing the source (and streamer(s) in some cases).
In addition to receiving the desired signal associated with reflections/refractions of the seismic wave 14, receivers 2 will also receive noise. Noise can come from a variety of sources which can affect the received seismic signals in different manners. In the case of multi-component data the noise characteristic may be different for each component in terms of frequency, coherency, location or amplitude. For example, hydrophone data may be relatively clean with high signal to noise ratio at all frequencies and vertical accelerometer data may be substantially noisier at frequencies below 30 Hz. Standard de-noising techniques either rely on the noise being incoherent (f-x-deconvolution (Canales, L. L., 1984, Random noise reduction: 54th Annual International Meeting, SEG, Expanded Abstracts, 525-527), projection filtering (Soubaras, R., 1994, Signal-preserving random noise attenuation by the f-x projection: 64th Annual International Meeting, SEG, Expanded Abstracts, 1576-1579), etc.) or that the noise is distinguishable in some other way (e.g., Radon demultiple discrimination on moveout).
De-noising techniques balance the efficiency of the de-noising and the preservation of the underlying signal. In practice it is often more important to protect the signal so that after processing, genuine information can be extracted. This can significantly reduce the de-noising efficiency. For that reason modern de-noising techniques try to differentiate signal and noise by including as many signal characteristics as possible such, as amplitude and direction, in order to discriminate the noise from the signal.
For example, various computer algorithms are known by those skilled in the art to process combinations of acquired seismic data to separate upcoming primary reflection wave-field from the ghosted and multiple reflection energy arising from transmitted and reflected energy re-reflected by the sea surface. However, such algorithms are complicated by the difference between the signal quality and signal to noise (S/N) ratio of marine multi-component sensor data in comparison with the pressure wave-field measured by hydrophones. The particle motion and hydrophone sensors have fundamentally different response characteristics and sensitivities. Noise characteristics differ due to their different responses to ambient noise, with motion sensors strongly influenced by the motion and vibration of the streamer as it is towed through the recording medium.
Accordingly, it would be desirable to provide methods and systems that avoid the afore-described problems and drawbacks, and which provide mechanisms for de-noising acquired seismic data.